This section is intended to introduce the reader to various aspects of art, which may be associated with exemplary embodiments of the present invention, which are described and/or claimed below. This discussion is believed to be helpful in providing the reader with information to facilitate a better understanding of particular techniques of the present invention. Accordingly, it should be understood that these statements are to be read in this light, and not necessarily as admissions of prior art.
Oil companies have been drilling and completing horizontal wells for over a decade. Many of these wells include long horizontal carbonate pay sections that require acid stimulation treatments to produce commercial rates.
Acid fracturing is a common method of well stimulation in which acid, typically hydrochloric acid, is injected into a reservoir with sufficient pressure to either fracture the formation or open existing natural fractures. Portions of the fracture face are dissolved by the acid flowing through the fracture. Effectiveness of the stimulation is determined by the length of the fracture which is influenced by the volume of acid used, its reaction rates, and the acid fluid loss from the fracture into the formation.
These horizontal wells typically require pre-drilled holes in the liners to facilitate fluid interval stimulation. The acid or simulation fluid needs to be diverted away from the holes after the interval is treated to additional sections that are intended to be treated.
Some wells are completed by spacing out pre-drilled holes along the un-cemented liner section. Effective placement of the acid treatment along the long horizontal section is operationally challenging. Currently, ball sealers along with the limited-entry perforating technique are used to divert the stimulation fluids. Conventional means of increasing stimulation interval coverage include dividing the lateral into smaller sections through use of bridge plugs and packers which increases completion cost and mechanical complexity.
One common prior art completion technique is often referred to as the open hole “Sprinkler System.” The system consists of running a pre-perforated, un-cemented liner in open hole and stimulating down the casing at the highest rate possible while remaining within the pressure ratings of the casing. Acid diversion along the entire lateral length is achieved by a combination of limited entry perforating, high injection rates and the use of ball sealers to plug off a portion of existing perforations and divert flow through other perforations. This technique is limited by the inability to select which perforations the ball sealers will seal. Subsequent production logs such as, radioactive tracer and temperature logs indicate that the entire lateral may only be partially treated with this technique with questionable true fracture extension away from the wellbore. This can present a challenge in maximizing recovery in a reservoir.
A method to improve the fracture geometry involves reducing the length of the lateral being treated while maintaining similar injection rates. This can be achieved by drilling shorter laterals or by dividing a long lateral into several sections and treating each independently. Treating smaller lateral sections effectively increases the rate per foot of reservoir being stimulated and can significantly increase the fracture geometry and improve ultimate performance. While drilling shorter laterals typically improves stimulation performance, it also typically increases costs as additional wells may be required to effectively deplete the reservoir. Therefore, segmenting longer laterals for stimulation purposes is a logical next step.
Recent improvements in open-hole packer technology provide the ability to mechanically isolate long laterals into separate shorter intervals and selectively stimulate each section. This “packer plus technology” is a mechanical diversion technique utilizing packers and bull plugs (kobes) to seal off perforations, and the travelling sub to knock off the bull plugs. This technique limits the treatment from the bottom up or from toe to heel in a horizontal interval.
To accomplish this, an open-hole anchor packer and a series of open hole mechanical set packers are run into the lateral section on drill pipe as part of the liner. The system is then spaced out as required to separate the targeted stimulation intervals. On top of the assembly, a hydraulic set liner top packer and setting tool is run and spaced out to land in the casing. Each packer is pinned to set at increasing hydraulic pressures starting from the bottom up. A pump out plug or ball seat is consecutively run downstream of the deepest packer to provide the seal necessary to induce internal pressure.
When on bottom, an open-hole anchor is set with hydraulic pressure down the drill pipe. The anchor is pinned to shear and set at a predetermined pressure which can be detected on the surface monitoring equipment. After setting the anchor, the down-hole pressure is bled off and compression pressure is slacked off onto the anchor before the remaining packers are set. This locks the liner in compression and prevents movement of the isolation packers while pumping the stimulation fluid due to temperature shrinkage. Each subsequent packer is consecutively set with increasing hydraulic pressures. Typical setting ranges for example, may be 8,620 Kilo Pascal (KPa) (1250 pressure per square inch (psi)), 10,300 KPa (1500 psi), 12,100 KPa (1750 psi) and 13,800 KPa (2000 psi). After all the packers have been successfully set and the annulus tested, right hand torque releases the setting tool and the drill pipe is recovered from the well. After recovery of the drill pipe, the drilling rig may be rigged down and moved off location in preparation for the stimulation.
The toe section of the liner system may be pre-perforated with holes spaced out as in the typical “Sprinkler System” design. Between the packers are a series of ported subs that are blanked off with small bull plugs (or kobes) that intrude into the internal diameter of the liner. A sub is a short length of pipe that is threaded on both ends with special features described above. These subs may be spaced out every 2nd or 3rd casing joint to cover the entire section. A traveling sub containing a ball seat is pinned just downstream of each open hole packer and is activated during the stimulation by dropping a large composite ball. This ball is pumped down the casing and into the liner until it reaches the corresponding seat. After seating, the pressure begins to rise until the traveling sub shears from the packer and begins sliding concentrically down the casing. This sub then knocks off each of the kobes in order exposing the frac ports. When the sub reaches the other end, it latches into the top of the lower packer and creates an inner and outer seal to prevent continued stimulation of the lower interval. The well is now configured to stimulate the middle interval without ever stopping the pumps. When this second stage treatment has been pumped, a slightly larger ball is dropped to expose the frac ports in the upper section and isolate from the middle interval. After clearing the frac equipment, the well is put on test and the balls flowed off seat and recovered at the surface.
A potential economic benefit exists from improving the acid frac stimulation effectiveness in some horizontal completions. Typical completion techniques span a wide range of cost and complexity and can have a significant impact on the economics of the project. As discussed above, one method to maximize the benefit of high treating rates to create fracture geometry involves mechanically separating open-hole laterals into several sections and treating each zone independently. Unfortunately, this technique has proven costly, slow and subject to high mechanical risk.
Further, other methods may involve coupling burst disk assemblies together along intervals of a wellbore and treating the intervals in a sequential manner from the toe to the heel or heel to the toe. See Intl. Appl. Pub. No. WO 03/056131. In the method, burst disk assemblies are utilized to treat individual intervals in a sequential manner from the toe to the heel or heel to the toe to allow pressure to build up for the following intervals. However, this method does not describe treating the production intervals with the most potential with the first treatment.
Accordingly there is a need to improve stimulation coverage while maximizing completion value. Preferably, this method would comprise an open hole mechanical isolation system and methodology to selectively stimulate separate intervals within a single lateral. This invention satisfies that need.
Other related material may be found in at least U.S. Pat. Nos. 3,637,020; 4,949,788; 5,005,649; 5,145,005; 5,156,207; 5,320,178; 5,355,956; 5,392,862; 5,950,733; 6,173,795; 6,189,618; U.S. Patent App. Pub. No. 2003/0070809; U.S. Patent App. Pub. No. 2003/0075324; and Intl. Appl. Pub. No. WO 03/056131. Further, additional information may also be found in Economides et al., Reservoir Simulation, Second Edition, 15-1 to 17-12 (1989); Dees et al., “Horizontal Well Stimulations Results in the Austin Chalk Formation, Pearsall Field, Tex.”, SPE 20683 (1990); Nelson et al., “Multiple Pad-Acid Fracs in a Deep Horizontal Well”, SPE 39943 (1998); Krawletz et al., “Horizontal Well Acidizing of a Carbonate Formation: A Case History of Lisburne Treatments Prudhoe Bay, Ala.”, SPE Production & Facilities 238-243 (1996).